November 5, 2012

Pierre Martinez Project Manager Systems Assessment & Facility Siting Division California Energy Commission 1516 Ninth Street, MS-15 Sacramento, CA 95814

SUBJECT: Final Determination of Compliance (FDOC) for Rio Mesa Solar Electric Generating Facility (11-AFC-4)

Dear Mr. Martinez: Rio Mesa Solar I, LLC and Rio Mesa Solar II, LLC, collectively the “Applicant” for the Rio Mesa Solar Electric Generating Facility project (“Rio Mesa SEGF”), submits the Applicant’s Final Determination of Compliance (FDOC) from the Mojave Desert Air Quality Management District (MDAQMD). If you have any questions, please do not hesitate to contact me. Sincerely,

Todd Stewart Senior Director of Project Development

DOCKETEDCalifornia Energy Commission

NOV. 07 2012

TN # 68401

11-AFC-4

Mojave Desert Air Quality Management District 14306 Park Avenue, Victorville, CA 92392-2310

760.245.1661 • fax 760.245.2699 Visit uur web site: http://www.mdaqma. ca.gol.

Eldon Heaston, Executive Director

November 1,2012

Todd Stewart, Project Manager Rio Mesa Solar 1999 Harrison Street, Suite 21 SO Oakland, California 94612

Subject: Final Determination of Compliance (FDOC) for the Rio Mesa Solar Project (CEC Docket No. 201l-AFC-04)

Dear Mr. Stewart:

The Mojave Desert Air Quality Management District (MDAQMD) has completed the FDOC on the proposed Rio Mesa Solar Project (Rio Mesa SEGF). The Preliminary Decision (POOe) was released for public comment on September 10, 2012. The public comment period ended October 10,2012. No written comments on the PDOe were received. Except for typographical error (Rule 475 and 476 grain loading, p. 11) corrections, the FDOC incorporates the PDOe in its entirety. As required by MDAQMD Rule I306(E)(3), this FDOC completes the MDAQMD review of the proposed project. Enclosed please find the FDOC for Rio Mesa SEGF.

Should you have any questions regarding this action or the enclosure, please contact Christian Anderson at (760) 245-1661, x 1846.

Sincerely,

~$ Alan De Salvio Supervising Air Quality Engineer

Enclosures: FDOC

cc: Pierre Martinez - CEC Project Manager email cc:

Wenjun Qian - CEC project staff member Tom Andrews - Sierra Research

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Chief, Air Permits Office USEPA Region IX Chief, Stationary Source Division CARB

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Final Determination of Compliance (Final New Source Review Document)

Rio Mesa Solar Electric Generating Facility; Located on the Palo Verde Mesa in Riverside

County, CA, approximately 13 miles southwest of Blythe.

Eldon Heaston

Executive Director

Mojave Desert Air Quality Management District

November 1, 2012

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Rio Mesa SEGF FDOC i

Table of Contents Table of Contents............................................................................................................................................................................... i List of Abbreviations......................................................................................................................................................................... ii 1. Introduction ................................................................................................................................................................................ 1 2. Project Location ......................................................................................................................................................................... 1 3. Description of Project................................................................................................................................................................. 2

Overall Project Emissions................................................................................................... 4 4. Control Technology Evaluation/BACT Determination ............................................................................................................... 6

Proposed Limits for each 249 MMBtu/hr Natural Gas Fired Boiler .................................. 6 Proposed Limits for each 15 MMBtu/hr Natural Gas Fired Boiler .................................... 6 Proposed Limits for each Internal Combustion Engine – Emergency Fire Pump and Emergency Generator (total of six engines) ....................................................................... 7

6. PSD Class I Area Protection ...................................................................................................................................................... 7 7. Air Quality Impact Analysis........................................................................................................................................................ 7

Findings............................................................................................................................... 8 Inputs and Methods............................................................................................................. 8

8. Health Risk Assessment and Toxics New Source Review............................................................................................................ 9 Findings............................................................................................................................... 9 Inputs and Methods............................................................................................................. 9

9. Offset Requirements.................................................................................................................................................................. 10 10. Applicable Regulations and Compliance Analysis.................................................................................................................. 10

Regulation II – Permits ..................................................................................................... 10 Regulation IV – Prohibitions ............................................................................................ 10 Regulation IX – Standards of Performance for New Stationary Sources......................... 11 Regulation XI - Source Specific Standards ...................................................................... 12 Regulation XIII – New Source Review ............................................................................ 12 Regulation XII – Federal Operating Permits .................................................................... 13 Maximum Achievable Control Technology Standards..................................................... 13

11. Conclusion .............................................................................................................................................................................. 14 12. Permit Conditions................................................................................................................................................................... 14

Auxiliary Boiler Authority to Construct Conditions ........................................................ 14 Nighttime Preservation Boiler Authority to Construct Conditions................................... 16 Emergency Generator Authority to Construct Conditions................................................ 17 Emergency Fire Suppression Water Pump Authority to Construct Conditions ............... 19

Appendix – Rio Mesa SEGF Emissions Calculations ....................................................................................................................... 1

ii

List of Abbreviations APCO Air Pollution Control Officer ATC Authority To Construct ATCM Airborne Toxic Control Measure BACT Best Available Control Technology CARB California Air Resources Board CATEF California Air Toxics Emission Factors CEC California Energy Commission CEMS Continuous Emissions Monitoring System CERMS Continuous Emission Rate Monitoring System CFR Code of Federal Regulations CH4 Methane CO Carbon Monoxide CTG Combustion Turbine Generator dscf Dry Standard Cubic Feet ERC Emission Reduction Credit °F Degrees Fahrenheit (Temperature) FDOC Final Determination of Compliance HAP Hazardous Air Pollutant HARP Hot Spots Analysis and Reporting Program HHV Higher Heating Value hp Horsepower hr Hour HRA Health Risk Assessment HRSG Heat Recovery Steam Generator HTF Heat Transfer Fluid LAER Lowest Achievable Emission Rate lb Pound MACT Maximum Achievable Control Technology µg/m3 Micrograms per cubic meter MDAQMD Mojave Desert Air Quality Management District MMBtu Millions of British Thermal Units n/a Not applicable NAAQS National Ambient Air Quality Standard NESHAP National Emission Standards for Hazardous Air Pollutants NO2 Nitrogen Dioxide NOx Oxides of Nitrogen NSPS New Source Performance Standard O2 Molecular Oxygen OEHHA Office of Environmental Health Hazard Assessment OLM Ozone Limiting Method o/o Owner/Operator PAH Polycyclic Aromatic Hydrocarbons PHPP Palmdale Hybrid Power Project PM2.5 Fine Particulate, Respirable Fraction ≤ 2.5 microns in diameter

Rio Mesa SEGF FDOC iii

PM10 Fine Particulate, Respirable Fraction ≤ 10 microns in diameter ppmvd Parts per million by volume, dry PSD Prevention of Significant Deterioration RSP Rapid Start Process SCAQMD South Coast Air Quality Management District SCLA Southern California Logistics Airport SCR Selective Catalytic Reduction SIP State Implementation Plan SO2 Sulfur Dioxide SOx Oxides of Sulfur STG Steam Turbine Generator TOG Total Organic Gases tpy Tons per Year USEPA United States Environmental Protection Agency VOC Volatile Organic Compounds

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Rio Mesa SEGF FDOC

1. Introduction The Mojave Desert Air Quality Management District (MDAQMD) received an Application for New Source Review (NSR) for the Rio Mesa Electric Solar Generating Facility (Rio Mesa SEGF) on October 12, 2011 and received a Request for Agency Participation and Application for Certification for the Rio Mesa SEGF on October 12, 2011. The MDAQMD subsequently deemed the application complete on November 14, 2011. The “Applicant”, for purposes of NSR and the AFC, comprises Rio Mesa Solar I, LLC, and Rio Mesa Solar II, LLC, owners of the two separate solar plants and certain shared facilities being proposed. For clarity and consistency, the MDAQMD will herein refer to this project as the “Rio Mesa SEGF” or “Project”. Project Permit Application History-Brief Originally submitted as one solar electric generating facility with three separate solar plants, the original proposed facility design has been altered twice. The District received correspondence and identified changes as noted below;

April 20, 2012: “Boiler Optimization” proposal. This proposal included a reduction in size and type of boilers proposed for the facility. The quantity of boilers, at each plant, were reduced from five to two. The three, large auxiliary boilers (500 MMBTU/hr) will be eliminated.

July 3, 2012: “Environmental Enhancement” proposal. This proposal consists of a

reduction in the number of solar plants at the facility, from three to two, and change in location of common area equipment. Proposed Rio Mesa Solar-III has been removed and likewise project interest by Rio Mesa Solar, LLC. The site at the facility for the common area equipment was relocated to the far northern reach of the Rio Mesa Solar-I solar field.

The Preliminary Decision (PDOC) was released for public comment on September 10, 2012. The public comment period ended October 10, 2012. No written comments on the PDOC were received. Except for typographical error (Rule 475 and 476 grain loading limit corrected, p. 11) corrections, the Final Determination of Compliance (FDOC) incorporates the PDOC in its entirety. As required by MDAQMD Rule 1306(E)(3), this FDOC completes the MDAQMD review of the proposed project.

2. Project Location The Project is a solar electric generating facility comprised of two 250 MW (nominal) solar plants (Rio Mesa SEGF total is 500 MW). Each 250 MW plant requires about 1,850 acres (or 2.9 square miles) of land to operate. The total area required for both plants, including the shared facilities, is approximately 3,805 acres. The proposed site is located on the Palo Verde Mesa in Riverside County, California, 13 miles southwest of Blythe. The project site has been designated non-attainment for the California ozone ambient air quality standard (CAAQS) and PM10 ambient air quality standards (CAAQS). The area is attainment or unclassified for all other standards and averaging times. The proposed site has been previously disturbed by military training operations during World War II, and investigative activities resulting from the proposed SunDesert Nuclear Power Plant by San Diego Gas and Electric (SDG&E) in the 1970s.

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3. Description of Project The proposed facility will consist of two 250 MW (nominal) solar plants. The proposed project will include two solar concentrating thermal power plants and a shared common area to include shared systems. Each solar concentration thermal power plant will utilize a solar power boiler, located on top of a dedicated concrete tower, and solar field based on heliostat mirror technology. The heliostat (mirror) fields will focus solar energy on the solar power boiler, referred to as “solar receiver steam generator” (SRSG) which converts the solar energy to superheated steam. In each plant, a Rankine cycle non-reheat steam turbine receiving this superheated steam will be directly connected to a rotating generator that generates and pushes the electricity onto the transmission system steam. Each power plant will generate electricity using solar energy as its primary fuel source. However, auxiliary boilers will be used to operate in parallel with the solar field during partial load conditions and occasionally in the afternoon when power is needed after the solar energy has diminished to a level that no longer will support solar-only generation of electricity. These auxiliary boilers will also assist with daily start-up of the power generation equipment and night time preservation. Each of the two solar units/power blocks will consist of a solar array field, one auxiliary steam boiler, one night-time preservation boiler that will provide overnight heat to systems, SRSG, steam turbine generator (SSG), emergency generator set, emergency fire pump system, various feed-water heaters and pumps, wet-surface air cooler (WSAC), and condensate polisher. Additionally, there will be mirror washing activities associated with each solar field. The shared facilities (located in the common area) will include a combined administration, control, maintenance and warehouse building, heliostat assembly building, evaporation ponds, groundwater wells, water treatment plant, and a common switchyard. These shared facilities will be jointly and equally owned by both project companies. Rio Mesa SEGF is proposing to install the following equipment, to be permitted, at each power block:

USEPA Tier 2 emergency diesel generator rated at 3633 bhp USEPA Tier 3 fire pump rated at 200 bhp Auxiliary natural gas fired boilers rated at 249 MMBtu/hr Nighttime preservation natural gas fired boiler rated at 15 MMBtu/hr

Rio Mesa SEGF is proposing to install the following equipment, to be permitted, at the common

area:

USEPA Tier 3 emergency diesel generator rated at 398 bhp USEPA Tier 3 fire pump rated at 200 bhp

The WSAC is exempt from District permit per Rule 219 (E)(4)(c) because it is not to be used for evaporative cooling of process water. The WSAC will be used to cool lube oils only. The internal combustion engines will meet all applicable California Air Resources Board (CARB) and U.S. Environmental Protection Agency (USEPA) Tier emissions standards depending upon engine size, year of manufacture, and service category. Additionally, the

Rio Mesa SEGF FDOC

engines will meet the requirements of the CARB Airborne Toxic Control Measure (ATCM) for Stationary Compression Ignition Engines and the USEPA NSPS for Diesel Engines. Proposed equipment specifications, for emissions sources located at each power block, are summarized as follows: Auxiliary Boiler

Manufacturer: Rentech or equivalent Model: D-Type Watertube or equivalent Fuel: Natural Gas Rated Heat Input: 249 MMBtu/hr @ HHV Fuel consumption: ~244,118 scf/hr (Gas HHV 1020 Btu/scf) Exhaust flow: 72,426 acfm Exhaust temperature: 300 degrees Fahrenheit (°F) Stack diameter: 5.50 feet Release height: 135 feet Low NOx burner/FGR (NOx, 9 ppmv @ 3% O2)

Nighttime Preservation Boiler

Manufacturer: Rentech or equivalent Model: D-Type Watertube or equivalent Fuel: Natural Gas Rated Heat Input: 15 MMBtu/hr @ HHV Fuel consumption: ~14,706 scf/hr (Gas HHV 1020 Btu/scf) Exhaust flow: 4,363 acfm Exhaust temperature: 300 degrees Fahrenheit (°F) Stack diameter: 1.50 feet Release height: 30 feet Low NOx burner/FGR (NOx, 9 ppmv @ 3% O2)

Fire Pump Engine

Manufacturer: Cummins CFP7E-F30 or equivalent Fuel: Diesel or distillate oil (15 ppmw S) Rated horsepower: 200 hp Fuel consumption: 12 gallons per hour (gph) Exhaust flow: 1,650 actual cubic feet per minute (acfm) Exhaust temperature: 975 degrees Fahrenheit (°F) Stack diameter: 0.33 feet Release height: 15 feet

Emergency Electrical Generator

Manufacturer: Caterpillar 3516C or equivalent Fuel: Diesel or distillate oil (15 ppmw S)

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Rated horsepower: 3633 hp Fuel consumption: 175 gallons per hour (gph) Exhaust flow: 19,600 actual cubic feet per minute (acfm) Exhaust temperature: 925 degrees Fahrenheit Stack diameter: 1.50 feet Release height: 26 feet

Proposed equipment specifications, for emissions sources located at common area, are summarized as follows: Fire Pump Engine

Manufacturer: Cummins CFP7E-F30 or equivalent Fuel: Diesel or distillate oil (15 ppmw S) Rated horsepower: 200 hp Fuel consumption: 12 gallons per hour (gph) Exhaust flow: 1,650 actual cubic feet per minute (acfm) Exhaust temperature: 975 degrees Fahrenheit (°F) Stack diameter: 0.33 feet Release height: 15 feet

Emergency Electrical Generator

Manufacturer: Caterpillar C9 ATAAC or equivalent Model: 250 eKW Fuel: Diesel or distillate oil (15 ppmw S) Rated horsepower: 398 Fuel consumption: 20 gph Exhaust flow: 2,250 acfm Exhaust temperature: 855 degrees Fahenreheit (°F) Stack diameter: 0.67 feet Release height: 18 feet

The only fuels to be combusted on-site will be California-certified low-sulfur low-aromatic diesel fuel used by the emergency fire pumps and the emergency generator engines, and pipeline- quality natural gas for the auxiliary and nighttime preservation boilers.

Overall Project Emissions Operation of the Project will result in emissions to the atmosphere of both criteria and toxic air pollutants from the proposed auxiliary boilers, nighttime preservation boilers, fire pumps, emergency generator engines, wet surface air coolers (WSAC), and mirror washing activities (excluding vehicle combustion). The WSAC (used only for cooling lube oils) and mirror washing activities are fugitive emission sources not permitted by the MDAQMD (exempt per Rule 219). Criteria pollutant emissions will consist primarily of nitrogen oxides (NOx), carbon monoxide (CO), volatile organic compounds (VOCs), sulfur oxides (SOx), and 10-micron and below particulate matter (PM10). Air toxic pollutants will consist of a combination of toxic gases and toxic particulate matter species. Tables 1 and 1A list the pollutants that may potentially be

Rio Mesa SEGF FDOC

emitted from the proposed Project. For natural gas-fired equipment, emissions calculations are based on the Higher Heating Value (HHV) of the natural gas fuel.

Maximum Annual Emissions Table 1 presents maximum annual facility operational emissions. Table 1A presents maximum annual facility hazardous air pollutant (HAP) emissions.

Table 1 – Rio Mesa SEGF Maximum Annual Operational Emissions (All emissions presented in tons per year)

NOx CO VOC SOx PM10 CO2e Rio Mesa SEGF Maximum 8.3 13.0 3.1 0.8 8.4 44513

Table 1A – Rio Mesa SEGF Maximum Annual HAP Emissions

(All emissions presented in pounds per year) Substance Total

Acetaldehyde 0.970481471

Acrolein 0.854768333 Copper 1.0E-07 DPM TAC 136.64 Ethylbenzene 2.158201863 Formaldehyde 3.867738529 Hexane 1.419146667 Naphthalene 0.219453235

PAHs (except naphthalene) (4) 0.073151078 speciated PAHs Benzo(a)anthracene 0.006895139 Benzo(a)pyrene 0.00459676 Benzo(b)fluoranthrene 0.006895139 Benzo(k)fluoranthrene 0.006895139 Chrysene 0.006895139 Dibenz(a,h)anthracene 0.00459676 Indeno(1,2,3-cd)pyrene 0.006895139 Propylene TAC 84.35003716 Toluene 8.358819118 Xylene 6.214804608

Total HAPS 26.0 Note: Total HAPS do not include Toxic Air

Contaminants (TAC) DPM or Propylene

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Maximum Daily Emissions Table 2 presents maximum daily facility emissions. Emissions for the auxiliary and nighttime boilers were calculated under worst case conditions. The calculations were made assuming five normal operations hours and two and one-half startup hours for the auxiliary boiler and assuming 16 normal hours and one startup hour for the nighttime boiler. Fire pump and emergency generator engines emissions were each calculated based on one-half hours per day (daily maintenance and testing hours). Daily emission calculations do not include fugitive emission sources.

Table 2 – SEGF Maximum Daily Operational Emissions NOx CO VOC SOx PM10

Pounds per day 88.1 111.4 24.1 6.6 17.8

4. Control Technology Evaluation/BACT Determination Best Available Control Technology (BACT) is required for any new or Modified Permit Unit which emits, or has the Potential to Emit (PTE), 25 pounds per day or more of any Nonattainment Air Pollutant or any new or Modified Facility which emits, or has the PTE 25 tpy or more of any Nonattainment Air Pollutant (MDAQMD Rule 1303(A)). The proposed project site is state non-attainment for ozone and PM10 and their precursors and unclassified or attainment for all other state and federal standards. Based on the maximum daily emissions from each proposed permit unit and/or facilitywide annual PTE, as calculated in Section 3 above and Appendix A, the proposed project equipment does not trigger BACT.

Proposed Limits for each 249 MMBtu/hr Natural Gas Fired Boiler Table 3 – Rio Mesa SEGF – Proposed Limits for Natural Gas Auxiliary Boilers*

Pollutant Limit Control NOx 9.0 ppm at 3% O2 Ultra low-NOx burner and Flue Gas Recirculation (FGR) VOC 12.6 ppm at 3% O2 PUC quality natural gas PM 0.005 lb/MMBtu PUC quality natural gas SOx 0.0021 lb/MMBtu PUC quality natural gas CO 25 ppm at 3% O2 Ultra low-NOx burner and FGR *Operating in normal mode.

Proposed Limits for each 15 MMBtu/hr Natural Gas Fired Boiler Table 4 – Rio Mesa SEGF – Proposed Limits for Natural Gas Nighttime Preservation Boilers*

Pollutant Limit Control NOx 9.0 ppm at 3% O2 Ultra low-NOx burner VOC 12.6 ppm at 3% O2 PUC quality natural gas PM 0.005 lb/MMBtu PUC quality natural gas SOx 0.0021 lb/MMBtu PUC quality natural gas CO 50 ppm at 3% O2 Ultra low-NOx burner and FGR *Operating in normal mode.

Rio Mesa SEGF FDOC

Proposed Limits for each Internal Combustion Engine – Emergency Fire Pump and Emergency Generator (total of six engines) The proposed engines meet the requirements of the NSPS for Stationary Compression Ignition Internal Combustion Engines (40 CFR Part 60, Subpart IIII) and the California State Airborne Toxic Control Measure for Stationary Compression Ignition Engines (17 CCR 93115). Note complying with the NSPS also deems the engines compliant with the RICE NESHAP. Complying with the NSPS and ATCM has been determined as BACT for the engines powering a fire pump or emergency generator. Table 5 – Rio Mesa SEGF – Proposed Limits for Stationary Emergency Standby Direct-Drive Fire Pump Engines Proposed Engine Size

NMHC + NOx (g/bhp-hr)

PM (g/bhp-hr)

CO (g/bhp-hr)

SOx

200 bhp 3.0 0.15 2.6 15 ppm S fuel Table 6 – Rio Mesa SEGF – Proposed Limits for Stationary Emergency Standby Diesel-Fueled CI Engines Proposed Engines

NMHC + NOx (g/bhp-hr)

PM (g/bhp-hr)

CO (g/bhp-hr)

SOx

3633 bhp 4.8 0.15 2.6 15 ppm S fuel 398 bhp 3.0 0.15 2.6 15 ppm S fuel

6. PSD Class I Area Protection The Clean Air Act (CAA) established the PSD permit program to prevent areas that currently have clean air from significant deterioration. The PSD permit program limits emissions by requiring permits for major stationary air pollution sources. The Rio Mesa SEGF did not evaluate the visibility reduction potential of project emissions on Prevention of Significant Deterioration (PSD) Class I areas. The Rio Mesa SEGF application does not constitute an application for a major facility, as the criteria pollutant emissions are well below the major source threshold, and therefore is not required by Rule 1302 (B)(1)(a)(v)(a) to conduct such an evaluation. The Rio Mesa SEGF is not a major source for any pollutant (including greenhouse gas) nor is it subject to the PSD requirements of Title I, Part C of the Federal Clean Air Act (42 U.S.C. §§7470-7492) which apply to major sources only, and therefore is in compliance with the PSD requirements of Rule 1300.

7. Air Quality Impact Analysis SEGF performed the ambient air quality standard impact analyses for CO, PM10, PM2.5, SO2 and NO2 emissions. The MDAQMD approves of the analysis methods used in these impact analyses and the findings of these impact analyses.

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Findings The impact analysis calculated a maximum incremental increase for each pollutant for each applicable averaging period, as shown in Table 8 below. When added to the maximum recent background concentration, the Rio Mesa SEGF did not exceed the most stringent (or lowest) standard for any pollutant except PM10, which is already in excess of the State standard without the project.

Table 8 – Rio Mesa SEGF – Maximum Ambient Air Quality Impacts Project

Impacta Background Total

Impactb Federal

Standard State

Standard Pollutant All values in µg/m3 NO2 (1 hour-max)

165 92.4 257 n/a 339

NO2 (1 hour-98th percentile)

160 78.0 171c 188

NO2 (annual) 0.19 17.0 17 100 57 PM10 (24 hour) 1.57 140 142 150 50 PM10 (annual) 0.47 20.4 21 n/a 20 PM2.5 (24 hour)d 0.27 18 18 35 n/a PM2.5 (annual)e 0.05 7.8 8 15 12 CO (1 hour) 158 1837 1995 40,000 23,000 CO (8 hour) 12 643 655 10,000 10,000 SO2 (1 hour) 2 136.6 139 196 655 SO2 (3 hour) 0.9 112.9 114 1300 n/a SO2 (24 hour) 0.07 18.4 19 n/a 105 SO2 (annual) 0.01 2.6 3 80 n/a

Table 8 Notes: a Modeling results represent total impacts from boilers, emergency engines, and fugitive dust from MWMs. b Total concentrations shown in this table are the sum of the maximum predicted impact and the maximum measured background concentration. Because the maximum impact will not occur at the same time as the maximum background concentration, the actual maximum combined impact will be lower. c Total concentrations shown for 1-hour NO2 are modeled impacts combined with concurrent hourly NO2 monitoring data (Tier 4 analysis in Section 3.6 of the modeling protocol). This value represents the five-year average of the annual 1-hr NO2 98th

percentile (modeled impact plus background) for each year (2006 to 2010) as required by June 28, 2010 EPA 1-hr NO2 NAAQS guidance document. d Background concentration shown is the three-year average of the 98th percentile values, in accordance with the form of the federal standard.

e Background value shown is the three-year average of the annual arithmetic mean, in accordance with the form of the standard.

Inputs and Methods Maximum emissions from both power blocks (excluding WSAC) were modeled. Emissions from the power blocks are presented above in Table 1. The meteorological data set used in this analysis combined surface meteorological data (e.g. wind speed and direction, temperature) from the Blythe Airport (2006 through 2010), surface data (cloud cover) from the McCarran Airport in Las Vegas, NV, and upper data from Tucson, AZ. Ambient air concentrations of ozone (O3), NO2, CO, PM10, and PM2.5 are recorded at monitoring stations in Riverside County. SO2 data is recorded from the Victorville, CA monitoring station. For determining NO2 impacts using a NOx

Rio Mesa SEGF FDOC

background, the hourly Ozone Limiting Method (OLM) for conversion of NOx to NO2 was used. The latest versions of AERMOD preprocessors were used to determine surface characteristics (AERSURFACE version 08009), process meteorological data (AERMET version 11059) and determine receptor slope factors (AERMAP version 11103). The AERMOD dispersion model (version 12060) was used to estimate ambient concentrations resulting from Rio Mesa SEGF emissions. The dispersion modeling was performed according to USEPA guidelines.

8. Health Risk Assessment and Toxics New Source Review Rio Mesa SEGF performed a Health Risk Assessment (HRA) for carcinogenic, non-carcinogenic chronic, and non-carcinogenic acute toxic air contaminants. The MDAQMD approves of the HRA methods and findings. Additionally, a screening HRA was conducted after the originally proposed plant design was altered. The MDAQMD approves of the screening HRA results.

Findings The HRA calculated a cancer risk of 3.6 per million at point of maximum impact (PMI). The calculated cancer risk at that maximally impacted residential receptor and worker is 0.1 and 0.6 per million, respectively. The maximum non-cancer chronic and acute hazard indices are both less than the significance level of 1.0 (0.0018 and 0.0007, respectively). Evaluated cancer risk from the proposed project is less than the significance level and the proposed project emits less than 10 tons per year of every single HAP and 25 tons per year of any combination of HAPs, no further toxics new source review is required for this project (Rule 1320(E)(2)(b)). Please refer to Table 1A above for a summary of project HAP emissions.

Inputs and Methods Rio Mesa SEGF will emit toxic air contaminants as products of natural gas combustion, diesel fuel combustion, equipment wear, mirror washing activities, and WSAC emissions. Combustion emissions were estimated using emission factors from USEPA and Ventura County APCD, and a speciation profile for polycyclic aromatic hydrocarbons (PAH) were derived from USEPA. WSAC emissions were estimated using engineering calculations for drift rate, and local anticipated water quality. The USEPA AERMOD dispersion model was used to estimate ambient concentrations of toxic air pollutants. Dispersion results were loaded into HARP via the HARP On-Ramp Program. The Hot Spots and Reporting Program (HARP, Version 1.4f, 2011) risk assessment model was used to estimate health risks due to exposure to emissions. Cancer risk was calculated using the Derived OEHHA Method. The AERMET/AERMOD meteorological dataset was used for the risk analysis.

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9. Offset Requirements MDAQMD Regulation XIII – New Source Review requires offsets for non-attainment pollutants and their precursors emitted by large, new sources. The Rio MESA SEGF does not have the PTE 25 tons or more per year of ozone precursors (NOx and VOC) or SOx, or 15 tons or more per year of PM10. Offsets are not required for the Rio Mesa SEGF.

Table 9 - Comparison of Rio Mesa SEGF – Emissions with Offset Thresholds

All emissions in tons per year NOx VOC SOx PM10 Maximum Annual Potential to Emit 8.3 3.1 0.8 8.4 Offset Threshold 25 25 25 15

10. Applicable Regulations and Compliance Analysis Selected MDAQMD Rules and Regulations will apply to the proposed project:

Regulation II – Permits Rule 212 – Standards For Approving Permits establishes baseline criteria for approving permits by the MDAQMD for certain projects. In accordance with these criteria, the proposed project accomplishes all required notices and emission limits through the PDOC and complying with stringent emission limitations set forth on permits.

Regulation IV – Prohibitions The following rules and discussions are specific to the proposed project. Rule 401 – Visible Emissions limits visible emissions opacity to less than 20 percent (or Ringelmann No. 1). During start up, visible emissions may exceed 20 percent opacity. However, emissions of this opacity are not expected to last three minutes or longer. In normal operating mode, visible emissions are not expected to exceed 20 percent opacity. Rule 402 – Nuisance prohibits facility emissions that cause a public nuisance. The proposed combustion equipment exhaust is not expected to generate a public nuisance due to the use of pipeline-quality natural gas as a fuel for the auxiliary boiler and nighttime boiler and low sulfur diesel fuel and limited use of the emergency IC engines. In addition, due to the location of the proposed project, no nuisance complaints are expected. Rule 403 – Fugitive Dust specifies requirements for controlling fugitive dust. The proposed project includes 3,805 acres of which only a small portion will be paved. As such, the remaining acreage will have the potential to generate a significant amount of fugitive dust if left untreated. Rio Mesa SEGF will apply an approved dust suppression coating to unpaved roadways within and around the solar fields. The proposed project is not expected to violate Rule 403.

Rio Mesa SEGF FDOC

Rule 404 – Particulate Matter – Concentration specifies standards of emissions for particulate matter concentrations. This rule does not apply to emissions from combustion of gaseous fuels in steam generators ie boilers. The sole use of ultra-low sulfur diesel fuel and certified emission IC engines will keep proposed project emission levels in compliance with Rule 404. Rule 407 – Liquid and Gaseous Air Contaminants limits carbon monoxide (CO) emissions to less than 2000 ppm measured on a dry basis, averaged over 15 minutes. The proposed project boilers will comply with this limit by permit condition resulting from this NSR action. IC engines are not subject to this rule. Rule 408 – Circumvention prohibits hidden or secondary rule violations. The proposed project is not expected to violate Rule 408. Rule 409 – Combustion Contaminants limits total particulate emissions on a density basis. The sole use of pipeline-quality natural gas as a fuel in the boilers and ultra-low sulfur diesel fuel in the emergency IC engines will keep proposed project emission levels in compliance with Rule 409. Rule 430 – Breakdown Provisions requires the reporting of breakdowns and excess emissions. The proposed project will be required to comply with Rule 430 by permit condition. Rule 431 – Sulfur Content in Fuels limits sulfur content in gaseous, liquid and solid fuels. The sole use of pipeline-quality natural gas (sulfur content equal to or less than 0.25 grains/100 dscf) as a fuel in the boilers and ultra-low sulfur diesel fuel (0.0015 percent by weight) in the emergency IC engines will keep proposed project fuels in compliance with Rule 431. Rule 475 – Electric Power Generating Equipment applies to non-Mobile Electric Power Generating Equipment having a maximum Rated Heat Input of more than 50 million Btu (MMBtu) per hour. This rule only applies to the auxiliary boilers (249 MMBTtu/hr) at this project. This rule limits emissions of NOx to 80 ppmv @ 3% O2; and PM not to exceed 0.01 gr/dscf @ 3% O2 and 11 lbs/hour. The auxiliary boilers will meet these requirements. Rule 476 - Steam Generating Equipment specifies monitoring and recordkeeping requirements and limits NOx emissions from steam generators rated above 50 MMBtu/hr to 125 ppmv @ 3% O2 and PM to less than 0.01 gr/scf and 11 lbs/hr. The auxiliary boilers are subject to and will comply with the recordkeeping/monitoring and emission limits by permit condition.

Regulation IX – Standards of Performance for New Stationary Sources Regulation IX is enacted to adopt by reference all the applicable provisions regarding standards of performance for new stationary sources as set forth in 40 Code of Federal Regulations, Part 60 (40 CFR 60). NSPS referenced in Regulation IX for which the facility has proposed equipment are discussed below. NSPS for Stationary Compression Ignition Internal Combustion Engines (40 CFR 60 Subpart IIII). Permit conditions for the diesel IC engines establish an engine certification (e.g. emission limits) requirement and monitoring provisions pursuant to the requirements of Subpart IIII.

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NSPS for Electric Utility Steam Generating Units (40 CFR 60 Subpart Da) is not applicable to the proposed auxiliary boilers as the boilers, rated at 249 MMbtu/hr are below the applicability threshold of 250 MMbtu/hr. NSPS for Industrial-Commercial-Institutional Steam Generation Units (40 CFR 60 Subpart Db) applies to new boilers with a maximum heat input greater than 100 MMBtu/hr. Subpart Db applies to the proposed auxiliary boilers, each rated at 249 MMbtu/hr. Subpart Db specifies emission limits for NOx, SOx, and PM. Pollutant Emission limit (lb/MMBtu) SOx 0.20 (§60.42b(k)(2)) PM none (record keeping/reporting only) (60.40b(a)) NOx (as NO2) 0.20 (§60.44b(a)) Permit conditions for the proposed boilers will establish compliance with emission limits for NOx, SOx, and PM. The emission limits of subpart Db are streamlined out by NSR permit conditions. Initial notification requirements of §60.49b(a) are not placed on permit.

NSPS for Small Industrial-Commercial-Institutional Steam Generating Units (40 CFR 60 Subpart Dc) applies to boilers constructed after June 9, 1989 and has max heat input between 10 and 100 MMBtu/hr. This applies to the Nighttime Preservation Boilers at the Rio Mesa SEGF. The sole use of natural gas in the Nighttime Preservation Boilers satisfies the requirements of Dc.

Regulation XI - Source Specific Standards Rule 1113 - Architectural Coatings limits VOC content of applied architectural coatings. The proposed project will comply through the purchase and use of compliant coatings. Rule 1157 – Boilers and Process Heaters 1157 applies to new and existing boilers, steam generators, and process heaters located within the Federal Ozone Non-attainment Area (FONA). This rule does not apply as the Rio Mesa SEGF is located outside the FONA. Rule 1158 – Electric Power Generating Facilities applies to any electrical generating steam boilers, including auxiliary boilers, or combined-cycle turbine units used in conjunction with an electrical generating steam boiler located in the FONA. This rule does not apply as the Rio Mesa SEGF is located outside the FONA. Rule 1160 – Internal Combustion Engines applies to stationary IC engines rated at 500 bhp and greater, located in the FONA. This rule will not apply as the proposed project is located outside the FONA.

Regulation XIII – New Source Review Rule 1300 – General ensures that Prevention of Significant Deterioration (PSD) requirements apply to all projects. The proposed project does not have the PTE 25 tons per year or more of a criteria pollutant and therefore is not a major source of emissions. As this facility is not a major source it is not subject to the PSD requirements Title I, Part C of the Federal Clean Air Act (42

Rio Mesa SEGF FDOC

U.S.C. §§7470-7492 which apply to major sources only and therefore is in compliance with the PSD requirements of Rule 1300. Rule 1302 – Procedure requires certification of compliance with the Federal Clean Air Act, applicable implementation plans, and all applicable MDAQMD rules and regulations. The ATC application package for the proposed project includes sufficient documentation to comply with Rule 1302(D)(5)(b)(iii). Permit conditions for the proposed project will require compliance with Rule 1302(D)(5)(a)(iii). Rule 1303 – Requirements requires BACT at major new sources and permit units which have the PTE to emit more than 25 pounds per day of criteria pollutants or facilities which have the PTE at or above the NSR major source thresholds. As this facility is not a major source nor does the individual equipment have the PTE 25 pounds per day or more, BACT is not required. Rule 1305 – Emissions Offsets this facility does not have the PTE a regulated air pollutant in an amount greater than or equal to MDAQMDs offset threshold amounts and therefore offsets are not required. Rule 1306 – Electric Energy Generating Facilities places additional administrative requirements on projects involving approval by the California Energy Commission (CEC). The proposed project will not receive an ATC without CEC’s approval of their Application for Certification, ensuring compliance with Rule 1306.

Regulation XII – Federal Operating Permits Regulation XII contains requirements for sources which must have a federal operating permit (FOP) and an acid rain permit (1200 (B)(1)(d)). The proposed project is subject to the acid rain program and as a result of, will be required to obtain a FOP. (Rule 1200 (B)(1)(d)). This facility is not subject to the provisions of Rule 1211- Greenhouse Gas Provisions of Federal Operating Permits because the annual CO2e emissions are less than 100,000 tpy.

Maximum Achievable Control Technology Standards Health & Safety Code §39658(b)(1) states that when USEPA adopts a standard for a toxic air contaminant pursuant to §112 of the Federal Clean Air Act (42 USC §7412), such standard becomes the Airborne Toxic Control Measure (ATCM) for the toxic air contaminant. Once an ATCM has been adopted it becomes enforceable by the MDAQMD 120 days after adoption or implementation (Health & Safety Code §39666(d)). The following MACT standards apply to specific emission devices at this facility;

• National Emission Standards for Reciprocating Internal Combustion Engines (40 CFR 63, Subpart ZZZZ) applies to the emergency fire pumps and generators located at the proposed facility. Compliance with this regulation for the engines proposed will be achieved through the purchase of engines complying with 40 CFR 60, Subpart IIII.

14

• National Emission Standards for Area Sources: Industrial/Commercial/Institutional Boilers (40 CFR, Subpart JJJJJJ) does not include requirements for natural gas-fired boilers, so this regulation will not apply to the boilers at the proposed Rio Mesa SEGF.

11. Conclusion The MDAQMD has reviewed the proposed project’s Application for New Source Review and subsequent supplementary information. The MDAQMD has determined that the proposed project, after application of the permit conditions given below, will comply with all applicable MDAQMD Rules and Regulations. This FDOC represents the MDAQMD final new source review document.

12. Permit Conditions The following permit conditions will be placed on the Authorities to Construct (ATC) for the project. Separate permits will be issued for each auxiliary boiler, nighttime preservation boiler, fire pump and emergency generator. The electronic version of this document contains a set of conditions that are essentially identical for each of multiple pieces of equipment, differing only in MDAQMD permit reference numbers. The signed and printed ATCs will have printed permits (with descriptions and conditions) in place of condition language listings.

Auxiliary Boiler Authority to Construct Conditions [Two – 249 MMBtu/hr Natural Gas Fired Auxiliary Boiler, Application Number: 00012024 and

0012031] 1. This boiler shall use only natural gas as fuel and shall be equipped with a meter

measuring fuel consumption in standard cubic feet. [1302(C)(2)(a)] 2. Prior to the expiration date each year, after the completion of construction the o/o shall

have this equipment tuned, as specified by Rule 1157(I), Tuning Procedure. [1302(C)(2)(a)]

3. The owner/operator shall maintain an operations log for this unit current and on-site (or at

a central location) for a minimum of five (5) years, and this log shall be provided to District, State and Federal personnel upon request. The log shall include, at a minimum, the daily and calendar year fuel use for this equipment in standard cubic feet, or BTU’s, and daily hours of operation. [Rule 1202(D) and 40 CFR Subpart Db]

4. Emissions from this equipment shall not exceed the following hourly emission limits,

operating at normal operating conditions and verified by fuel use and/or compliance tests: a. NOx as NO2: 2.72 lb/hr (0.0109 lb/MMBtu) (based on 9.0 ppmvd corrected to 3%

oxygen and averaged over one hour). b. CO: 4.60 lb/hr (based on 25 ppmvd corrected to 3% oxygen and averaged over one hour). c. VOC as CH4: 1.32 lb/hr.

Rio Mesa SEGF FDOC

d. SOx as SO2: 0.52 lb/hr (0.0021 lb/MMBtu), based on 0.75 gr/100 dscf. e. PM10: 1.25 lb/hr.

[District Rule 1302(C)(2)(a) and Rule 1304 (D)(1)(a)]

5. The o/o shall perform initial compliance tests on this equipment in accordance with the MDAQMD Compliance Test Procedural Manual. The test report shall be submitted to the District within 180 days of initial start up. The following compliance tests are required: a. NOx as NO2 in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Methods 7E or equivalent). b. CO in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Method 10). c. VOC as CH4 in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Methods 25A and 18). d. SOx as SO2 in ppmvd at 3% oxygen and lb/hr. e. PM10 in mg/m3 at 3% oxygen and lb/hr (measured per USEPA Reference Methods 201A and 202 or CARB Method 5).

[New Source Review-Regulation XIII, 40 CFR Subpart A - §60.8]

6. The o/o shall perform annual compliance tests on this equipment in accordance with the MDAQMD Compliance Test Procedural Manual. The test report shall be submitted to the District no later than six weeks prior to the expiration date of this permit. The following compliance tests are required: a. NOx as NO2 in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Methods 7E). b. CO in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Method 10). c. VOC as CH4 in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Methods 25A and 18). d. SOx as SO2 in ppmvd at 3% oxygen and lb/hr. e. PM10 in mg/m3 at 3% oxygen and lb/hr (measured per USEPA Reference Methods 201A and 202 or CARB Method 5).

[New Source Review-Regulation XIII, Periodic Monitoring] 7. This boiler shall be operated in compliance with all applicable requirements of 40 CFR

60 Subpart Db - Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units (NSPS Db).

8. Records of fuel supplier certifications of fuel sulfur content shall be maintained to

demonstrate compliance with the sulfur dioxide and particulate matter emission limits. [New Source Review-Regulation XIII, 40 CFR Subsection 60.49b(r)] 9. The o/o shall continuously monitor and record fuel flow rate and flue gas oxygen level.

[NSPS Db]

10. In lieu of installing CEMs to monitor NOx emissions, and pursuant to 40 CFR 60 Subpart Db, Section 60.49b(c), the owner/operator shall monitor boiler operating conditions and estimate NOx emission rates per a District approved emissions estimation plan. The plan shall be based on the initial source test and annually pursuant to condition 6. The plan shall include test results, operating parameters, analysis, conclusions and proposed NOx

16

estimating relationship consistent with established emission chemistry and operational effects.

This initial plan shall be submitted to the District for approval within 360 days of the initial startup. Any proposed changes to a District-approved plan shall include subsequent test results, operating parameters, analysis, and any other pertinent information to support the proposed changes. The District must approve any emissions estimation plan or revision for estimated NOx emissions to be considered valid. [40 CFR 60.49b(c)]

11. The o/o shall comply with all applicable recordkeeping and reporting requirements of NSPS Db.

12. This boiler shall not burn more than 1.3 MMSCF of natural gas in any single day, and no

more than 294.8 MMSCF in any calendar year. a. These limits shall not apply during the facility commissioning period. The commissioning period shall begin the first time fuel is fired in the boiler. The commissioning period shall end when the facility achieves commercial operation, but no later than 180 days after first fire.

13. This equipment shall exhaust through a stack at a minimum height of 135 feet. [1302(C)(2)(a)] 14. This facility shall not emit more than 9.9 t/y of a single HAP and 24.9 t/y of all HAP's.

To ensure compliance, the owner/operator shall calculate and record the annual emissions of Federal Hazardous Air Pollutants (HAP's) in tons per year (t/y) on a calendar year basis (January 1 through December 31). The list of HAP's can be found in Section 112(b)(1) of the Federal Clean Air Act or at web site: http://www.epa.gov/ttn/atw/188polls.html

15. The owner/operator shall submit a complete federal operating permit application to the

District no later than 12 months from the date this facility commences operation. [Rule 1200 (B)(1)(d) and 1202 (B)(3)(c)(ii)]

16. The o/o shall submit a complete Acid Rain permit application, including a compliance plan, to the District at least 24 months prior to commencing operation. [Rule 1210(C)(1)(a) and 1210(D)(1)(a)]

Nighttime Preservation Boiler Authority to Construct Conditions [Two – 15 MMBtu/hr Natural Gas Fired Nighttime Preservation Boiler, Application Number:

00012025 and 0012032] 1. This boiler shall be operated in compliance with all applicable requirements of 40 CFR

60 Subpart Dc - Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units (NSPS Dc).

2. This boiler shall use only natural gas as fuel and shall be equipped with a meter

measuring fuel consumption in standard cubic feet. [[1302(C)(2)(a)]

Rio Mesa SEGF FDOC

3. The owner/operator shall maintain an operations log for this unit current and on-site (or at

a central location) for a minimum of five (5) years, and this log shall be provided to District, State and Federal personnel upon request. The log shall include, at a minimum the amount of fuel combusted during each operating day. [40 CFR 60.48c(g)(1)]

4. Emissions from this equipment shall not exceed the following hourly emission limits,

operating at normal operating conditions and verified by fuel use, tuneups, and/or compliance tests:

a. NOx as NO2: 0.16 lb/hr (based on 9.0 ppmvd corrected to 3% oxygen and averaged over one hour). b. CO: 0.55 lb/hr (based on 50 ppmvd corrected to 3% oxygen and averaged over one hour). c. VOC as CH4: 0.08 lb/hr. d. SOx as SO2: 0.03 lb/hr (based on 0.75 gr/100 dscf). e. PM10: 0.08 lb/hr.

[District Rule 1302(C)(2)(a) and Rule 1304 (D)(1)(a)] 5. The o/o shall perform initial compliance tests on this equipment in accordance with the

MDAQMD Compliance Test Procedural Manual. The test report shall be submitted to the District within 180 days of initial start up. The following compliance tests are required: a. NOx as NO2 in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Methods 7E or equivalent). b. CO in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Method 10). c. VOC as CH4 in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Methods 25A and 18). d. SOx as SO2 in ppmvd at 3% oxygen and lb/hr. e. PM10 in mg/m3 at 3% oxygen and lb/hr (measured per USEPA Reference Methods 201A and 202 or CARB Method 5).

[New Source Review-Regulation XIII, 40 CFR Subpart A - §60.8] 6. The o/o shall perform annual compliance tests on this equipment in accordance with the

MDAQMD Compliance Test Procedural Manual. The test report shall be submitted to the District no later than six weeks prior to the expiration date of this permit. The following compliance tests are required: a. NOx as NO2 in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Method 7E). b. CO in ppmvd at 3% oxygen and lb/hr (measured per USEPA Reference Method 10).

[1302(C)(2)(a) and Periodic Monitoring] 7. Prior to the expiration date each year, after the completion of construction the o/o shall

have this equipment tuned, as specified by Rule 1157(I), Tuning Procedure.

Emergency Generator Authority to Construct Conditions [Power Blocks I and II: Two – 3,633 hp emergency IC engine each driving a generator, Application Number: 00012026 and 00012023.

18

Common Area: One – 398 hp emergency IC engine driving a generator, Application Number 00012035] 1. This engine, certified in accordance with 40 CFR Part 89, and after treatment control

device (if any) shall be installed, operated and maintained according to the manufacturer's emission-related written instructions. Further, the owner/operator shall change only those emission-related settings that are permitted by the manufacturer. Unless otherwise noted, this equipment shall also be operated in accordance with all data and specifications submitted with the application for this permit. [40 CFR Part 60 Subparts 60.4205, and 60.4211]

2. This unit shall only be fired on ultra-low sulfur diesel fuel, whose sulfur concentration is less

than or equal to 0.0015% (15ppm) on a weight per weight basis per CARB Diesel or equivalent requirements. [17 CCR 93115; 60.4207(b)]

3. A non-resettable hour meter with a minimum display capability of 9,999 hours shall be

installed and maintained on this unit to indicate elapsed engine operating time. [Title 17 CCR §93115.10(e)(1)]. District and State Only

4. This unit shall not be used to provide power during a voluntary agreed to power outage and/or

power reduction initiated under an Interruptible Service Contract (ISC); Demand Response Program (DRP); Load Reduction Program (LRP) and/or similar arrangement(s) with the electrical power supplier. [17 CCR 93115] [40 CFR 60 Subpart IIII allowance for DRP streamlined out.]

5. This unit shall be limited to use for emergency power, defined as in response to a fire or

when commercially available power has been interrupted. In addition, this unit shall be operated no more than 0.5 hrs per day for a total of 50 hours per year for testing and maintenance. [[District Rule 1302(C)(2)(a) and Rule 1304 (D)(1)(a)] and 17 CCR 93115] [Hours allowed by 60.42(f) streamlined out.]

6. The owner/operator shall maintain an operations log for this unit current and on-site (or at a

central location) for a minimum of five (5) years, and this log shall be provided to District, State and Federal personnel upon request. The log shall include, at a minimum, the information specified below: a. Date of each use and duration of each use (in hours); b. Reason for use (testing & maintenance, emergency, required emission testing, etc.); c. Monthly and calendar year operation in terms of fuel consumption (in gallons) and total hours [17 CCR 93115]; and, d. Fuel sulfur concentration (the o/o may use the supplier's certification of sulfur content if it is maintained as part of this log.) [17 CCR 93115]

7. This unit is subject to the requirements of the Airborne Toxic Control Measure (ATCM) for

Stationary Compression Ignition Engines (17 CCR §93115) and 40 CFR Part 60, Subpart IIII (NSPS). In the event of conflict between these conditions and the ATCM or NSPS, the more stringent requirements shall govern.

Rio Mesa SEGF FDOC

Emergency Fire Suppression Water Pump Authority to Construct Conditions [Three - 200 hp emergency IC engine each driving a fire suppression water pump, Application Number: 00012034, 00012036, and 00012027] 1. This engine, certified in accordance with 40 CFR Part 89, and after treatment control

device (if any) shall be installed, operated and maintained according to the manufacturer's emission-related written instructions. Further, the owner/operator shall change only those emission-related settings that are permitted by the manufacturer. Unless otherwise noted, this equipment shall also be operated in accordance with all data and specifications submitted with the application for this permit. [40 CFR Part 60 Subparts 60.4205 and 60.4211]

2. This unit shall only be fired on ultra-low sulfur diesel fuel, whose sulfur concentration is less

than or equal to 0.0015% (15ppm) on a weight per weight basis per CARB Diesel or equivalent requirements. [17 CCR 93115; 60.4207(b)]

3. A non-resettable hour meter with a minimum display capability of 9,999 hours shall be

installed and maintained on this unit to indicate elapsed engine operating time. [Title 17 CCR §93115.10(e)(1)]. District and State Only

4. This unit shall be limited to use for emergency power, defined as in response to a fire or

when commercially available power has been interrupted. In addition, this unit shall be operated no more than 0.5 hrs per day for a total of 50 hours per year for testing and maintenance. The 50 hour limit can be exceeded when the emergency fire pump assembly is driven directly by a stationary diesel fueled CI engine operated per and in accord with the National Fire Protection Association (NFPA) 25 - "Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems," 1998 edition. This requirement includes usage during emergencies. [[District Rule 1302(C)(2)(a) and Rule 1304 (D)(1)(a)] and 17 CCR 93115.3(n)] [Hours allowed by federal regulation 40 CFR 60.42(f) “streamlined out” as these permit requirements are more stringent than the federal regulatory requirements.]

5. The owner/operator shall maintain an operations log for this unit current and on-site (or at a

central location) for a minimum of five (5) years, and this log shall be provided to District, State and Federal personnel upon request. The log shall include, at a minimum, the information specified below: a. Date of each use and duration of each use (in hours); b. Reason for use (testing & maintenance, emergency, required emission testing, etc.); c. Monthly and calendar year operation in terms of fuel consumption (in gallons) and total hours [17 CCR 93115]; and, d. Fuel sulfur concentration (the o/o may use the supplier's certification of sulfur content if it is maintained as part of this log.) [17 CCR 93115]

6. This unit is subject to the requirements of the Airborne Toxic Control Measure (ATCM) for

Stationary Compression Ignition Engines (17 CCR §93115) and 40 CFR Part 60, Subpart IIII (NSPS). In the event of conflict between these conditions and the ATCM or NSPS, the more stringent requirements shall govern.

20

Rio Mesa SEGF FDOC

Appendix – Rio Mesa SEGF Emissions Calculations

2

Auxilliary Boilers Powerblocks 1 and 2 number of boilers 2Application No.'s 12024 and 12031

Normal Mode Startup Mode*MMBtu/hr 249 31 *provided by applicant, confidential emission spreadsheetSCFH 244,118 30,392 Hours shown are equivalent full load hours; boilers may operate more hours on some days and/or at lower loads. See text.SCFD 1,220,588 75,980 1,296,569 *Hours/day 5 2.5days/week 7 7weeks/yr 52 52*hrs/yr 1100 865 expected startup hours

Operating Modes Combined-Per Unitemissions emissions

lb/MM cu.ft. lb/MMBtu lb/hr lb/day lb/yr lb/hr lb/day lb/yrNormal NOx 9 ppm @ 3% % O2 1.254 0.01092 2.72 13.60 2991.79 5.43 20.37 5334.98

CO 25 ppm @ 3% % O2 2.120 0.01847 4.60 22.99 5058.58 9.18 34.44 9020.49VOC (as CH4) 12.6 ppm @ 3% % O2 0.611 0.00532 1.32 6.62 1456.87 2.65 9.93 2600.17

SOx 0.00210 0.52 2.61 575.19 0.59 2.78 631.50PM10 0.00500 1.25 6.23 1369.50 1.56 7.00 1637.65

Startup NOx 72 ppm @ 3% % O2 10.033 0.08738 2.71 6.77 2343.19CO 200 ppm @ 3% % O2 16.963 0.148 4.58 11.45 3961.91

VOC (as CH4) 101 ppm @ 3% % O2 4.895 0.043 1.32 3.30 1143.29SOx 0.75 grains/100 scf 0.0021 0.07 0.16 56.31

PM10 0.010 0.31 0.78 268.15

Fuel Heat Value: 1020 BTU/SCFFd 8710 DSCF exhaust per MMBtu in

Calculated Values (per boiler):Fuel Usage: 1323 MMBtu/Day

300715 MMBtu/yr1,296,569 SCFD

294.8 MMSCFY

Calculation of Noncriteria Pollutant Emissions from Auxiliary BoilersSpeciated PAHs (except naphthalene)

Mean EF Adjusted EF

(Note 1) (Note 5) lb/hrlb/yr, both

boilersPropylene 1.55E-02 3.79E-03 4.58E+00 9.16E+00 Benzo(a)anthracene 1.80E-06 1.58E-05 3.85E-06 9.31E-03Hazardous Air Pollutants Benzo(a)pyrene 1.20E-06 1.05E-05 2.57E-06 6.21E-03Acetaldehyde 9.00E-04 2.20E-04 2.65E-01 5.31E-01 Benzo(b)fluoranthrene 1.80E-06 1.58E-05 3.85E-06 9.31E-03Acrolein 8.00E-04 1.95E-04 2.36E-01 4.72E-01 Benzo(k)fluoranthrene 1.80E-06 1.58E-05 3.85E-06 9.31E-03Benzene 1.70E-03 4.15E-04 5.01E-01 1.00E+00 Chrysene 1.80E-06 1.58E-05 3.85E-06 9.31E-03Ethylbenzene 2.00E-03 4.88E-04 5.90E-01 1.18E+00 Dibenz(a,h)anthracene 1.20E-06 1.05E-05 2.57E-06 6.21E-03Formaldehyde 3.60E-03 8.79E-04 1.06E+00 2.12E+00 Indeno(1,2,3-cd)pyrene 1.80E-06 1.58E-05 3.85E-06 9.31E-03Hexane 1.30E-03 3.17E-04 3.83E-01 7.67E-01 Total 1.14E-05 1.00E-04 2.44E-05 5.90E-02Naphthalene 3.00E-04 7.32E-05 8.84E-02 1.77E-01

1.00E-04 2.44E-05 2.95E-02 5.90E-02Toluene 7.80E-03 1.90E-03 2.30E+00 4.60E+00Xylene 5.80E-03 1.42E-03 1.71E+00 3.42E+00

5.93E-03 7.16E+00 1.43E+01Notes:

(1) All factors from Ventura County APCD, "AB2588 Combustion Emission Factors," Natural Gas Fired External Combustion Equipment >100 MMBtu/hr. Available at http://www.vcapcd.org/pubs/Engineering/AirToxics/combem.pdf(2) Based on maximum hourly boiler heat input of 0.2441 MMscf/hr(3) Based on total annual heat input of 294.8 MMscf/yr(4) Total PAHs, excluding naphthalene. See speciation below.(5) Emission factors for individual PAHs obtained from AP-42, Table 1.4-3, then adjusted proportionally so that total of "Adjusted EF" equals Total PAH EF of 1.0 E-04 lb/MMscf per Ventura County factors.

Per Unitemission factor

Operating Mode

PAHs (except naphthalene) (4)

Total HAPs

Emissions

Compound

Emission Factor,

lb/MMcf (1)

Maximum Hourly

Emissions, lb/hr per boiler(2)

Annual Emissions (3)

lb/yr per boilerlb/yr, both

boilers

Rio Mesa SEGF FDOC 3

Nighttime Preservation Boilers

Powerblocks 1 and 2number of boilers 2

Application No.'s 12025 and 12032

Normal Mode Startup Mode

MMBtu/hr 15 1.9 Hours shown are equivalent full load hours; boilers may operate more hours on some days and/or at lower loads. See text.

SCFH 14,706 1,863

SCFD 235,294 1,863

Hours/day 16 1

days/week 7 7

weeks/yr 52 52

hrs/yr 4780 345 expected start-up hours

emissions emissions

lb/MM cu.ft. lb/MMBtu lb/hr lb/day lb/yr lb/hr lb/day lb/yr

Normal NOx 9 ppm @ 3% % O2 1.254 0.01092 0.16 2.62 783.17 0.33 2.79 840.45

CO 50 ppm @ 3% % O2 4.241 0.03694 0.55 8.86 2648.41 1.12 9.43 2842.11

VOC (as CH4) 12.6 ppm @ 3% % O2 0.611 0.00532 0.08 1.28 381.37 0.14 1.34 403.51

SOx 0.00210 0.03 0.50 150.57 0.04 0.51 151.95

PM10 0.00500 0.08 1.20 358.50 0.09 1.22 365.06

Startup NOx 72 ppm @ 3% % O2 10.033 0.08738 0.17 0.17 57.28

CO 400 ppm @ 3% % O2 33.926 0.295 0.56 0.56 193.70

VOC (as CH4) 80 ppm @ 3% % O2 3.877 0.034 0.06 0.06 22.14

SOx 0.75 grains/100 scf 0.0021 0.00 0.00 1.38

PM10 0.010 0.02 0.02 6.56

Fuel Heat Value: 1020 BTU/SCF

Fd 8710 DSCF exhaust per MMBtu in

Calculated Values:

Fuel Usage: 240 MMBtu/Day

72,356 MMBtu/yr

237,157 SCFD

71 MMSCFY

Calculation of Noncriteria Pollutant Emissions from Nighttime Boilers

Speciated PAHs (except naphthalene)

Mean EF Adjusted EF

(Note 1) (Note 5) lb/hrlb/yr, both

boilers

Propylene 5.30E-01 7.79E-03 3.76E+01 7.52E+01 Benzo(a)anthracene 1.80E-06 1.58E-05 2.32E-07 2.24E-03

Hazardous Air Pollutants Benzo(a)pyrene 1.20E-06 1.05E-05 1.55E-07 1.49E-03

Acetaldehyde 3.10E-03 4.56E-05 2.20E-01 4.40E-01 Benzo(b)fluoranthrene 1.80E-06 1.58E-05 2.32E-07 2.24E-03

Acrolein 2.70E-03 3.97E-05 1.92E-01 3.83E-01 Benzo(k)fluoranthrene 1.80E-06 1.58E-05 2.32E-07 2.24E-03

Benzene 5.80E-03 8.53E-05 4.11E-01 8.23E-01 Chrysene 1.80E-06 1.58E-05 2.32E-07 2.24E-03

Ethylbenzene 6.90E-03 1.01E-04 4.89E-01 9.79E-01 Dibenz(a,h)anthracene 1.20E-06 1.05E-05 1.55E-07 1.49E-03

Formaldehyde 1.23E-02 1.81E-04 8.73E-01 1.75E+00 Indeno(1,2,3-cd)pyrene 1.80E-06 1.58E-05 2.32E-07 2.24E-03

Hexane 4.60E-03 6.76E-05 3.26E-01 6.53E-01 Total 1.14E-05 1.00E-04 1.47E-06 1.42E-02

Naphthalene 3.00E-04 4.41E-06 2.13E-02 4.26E-021.00E-04 1.47E-06 7.09E-03 1.42E-02

Toluene 2.65E-02 3.90E-04 1.88E+00 3.76E+00

Xylene 1.97E-02 2.90E-04 1.40E+00 2.79E+00

1.21E-03 5.82E+00 1.16E+01

Notes:

(1) All factors from Ventura County APCD, "AB2588 Combustion Emission Factors,"

Natural Gas Fired External Combustion Equipment >100 MMBtu/hr. Available at

http://www.vcapcd.org/pubs/Engineering/AirToxics/combem.pdf

(2) Based on maximum hourly boiler heat input of 0.015 MMscf/hr

(3) Based on total annual heat input of 70.9 MMscf/yr

(4) Total PAHs, excluding naphthalene. See speciation below.

(5) Emission factors for individual PAHs obtained from AP-42, Table 1.4-3,

then adjusted proportionally so that total of "Adjusted EF"

equals Total PAH EF of 1.0 E-04 lb/MMscf per Ventura County factors.

Total HAPs

Emissions

Compound

Emission Factor,

lb/MMcf (1)

Maximum Hourly

Emissions, lb/hr per boiler(2)

Annual Emissions (3)

lb/yr per boiler

lb/yr, both boilers

PAHs (except naphthalene) (4)

Per Unit

emission factor

Operating Mode

Operating Modes Combined-Per Unit

4

Diesel Fire PumpPower Blocks 1, 2, and Common Area

Max Day AnnualArea App No. *Equipment bhp Hours Hours NOx CO VOC SO2 PM10 NOx CO VOC SO2 PM10 NOx CO VOC SO2 PM10

Power Block 1 12027Cummins CFP7E-F30 12 200 0.5 50 1.32 1.15 0.08 0.003 0.07 0.7 0.6 0.0 0.0 0.0 66.1 57.3 4.0 0.1 3.3

Power Block 2 12034Cummins CFP7E-F30 12 200 0.5 50 1.32 1.15 0.08 0.003 0.07 0.7 0.6 0.0 0.0 0.0 66.1 57.3 4.0 0.1 3.3

Common Area 12036Cummins CFP7E-F30 12 200 0.5 50 1.32 1.15 0.08 0.003 0.07 0.7 0.6 0.0 0.0 0.0 66.1 57.3 4.0 0.1 3.3

*or equivalent 66.1 57.3 4.0 0.1 3.30.033 0.029 0.002 0.000 0.002

Substance EmFac gm/bhp-hrNOx 3CO 2.6

VOC 0.18SO2 0.006

PM10 0.15

Totals

EmFac gm/bhp-hr lb/yrDPM 1.50E-01 9.92E+00

Notes:Criteria emissions data except SOx from manufacturer, toxics from MDAQMD. Diesel PM equal to PM10 Estimated SOX emission factor calculated from estimated max fuel consumption rate, calculated below:gal/hr X 7.21 lbs/gal X 453.59 g/lb X 0.0015/100 (sulfur) X 1/ bhp X 64.06 gSO2/32.06gS = g/bhp-hr

Total Tons

Max Daily (pounds) Max Annual (pounds)Fuel Use Rate (gph)

EmFac pounds/hour

Total Pounds

Rio Mesa SEGF FDOC 5

Emergency GensetPower Blocks 1 and 2, and Common Area

Max Day AnnualArea App No. *Equipment bhp Hours Hours NOx CO VOC SO2 PM10 NOx CO VOC SO2 PM10 NOx CO VOC SO2 PM10Power Block 1 12026 Caterpillar 3516C 175 3633 0.5 50 38.45 20.82 1.34 0.038 1.20 19.2 10.4 0.7 0.0 0.6 1922.3 1041.2 66.8 1.9 60.1Power Block 2 12033 Caterpillar 3516C 175 3633 0.5 50 38.45 20.82 1.34 0.038 1.20 19.2 10.4 0.7 0.0 0.6 1922.3 1041.2 66.8 1.9 60.1

Common Area 12035Caterpillar C9 ATAAC 20.0 398 0.5 50 2.63 2.28 0.15 0.00 0.13 1.3 1.1 0.1 0.0 0.1 131.6 114.1 7.5 0.2 6.6

*or equivalent 1922.3 1041.2 66.8 1.9 60.10.961 0.521 0.033 0.001 0.030

SubstancePower Block 1

and 2 CommonNOx 4.8 3CO 2.6 2.6

VOC 0.17 0.17SO2 0.005 0.005

PM10 0.15 0.15

Totals

lb/yrDPM 1.50E-01 1.27E+02

Notes:

Criteria emissions data except SOx from manufacturer, toxics from MDAQMD. Diesel PM equal to PM10 Estimated SOX emission factor calculated from estimated max fuel consumption rate, calculated below:gal/hr X 7.21 lbs/gal X 453.59 g/lb X 0.0015/100 (sulfur) X 1/ bhp X 64.06 gSO2/32.06gS = g/bhp-hr

Max Daily (pounds) Max Annual (pounds)

Total PoundsTotal Tons

EmFac gm/bhp-hr

EmFac gm/bhp-hr

Fuel Use Rate (gph)

EmFac pounds/hour

6

Fugitive Emissions from Mirror Cleaning Activities (stationary emission sources)Rio Mesa Solar Electric Generating FacilityRevised June 2012

Cleaning operations occur 365 days/yr20 hrs/day average

VMT/yr 18,900FFT MWM operation:

0.30 5,632 2,700 VMT/yr per FFT MWM0.03 563 18,900 VMT/yr (total per plant)

Smaller vehicles: VMT/yr 4,0000.17 684

NT MWM operation:145 HP

PM10 (road dust) 6,316 12,632 1 NT vehicle per plant64,240 gal/yr of fuel (total per plant, NT MWMs)

Notes: 4,000 VMT/yr (total per plant)

PM10 (road dust)

Total, all activitiesPer Power Block,

lb/yr

Unpaved road dust factors from construction emissions calculations; 90% control.

Total Both Power Blocks, lb/yr

Emission Factor

Emissions Per Plant(lb/year)

PollutantLarger vehicles:

PM10 (road dust) PM2.5 (road dust) (lb/VMT)

Rio Mesa SEGF FDOC 7

Calculation of Wet Surface Air Cooler EmissionsRio Mesa Solar Electric Generating FacilityRevised April 2012

Water Flow Rate, 10E6 lbm/hr 2.00Water Flow Rate, gal/min 4,000Drift Rate, % 0.0005Drift, lbm water/hr 10.00

TDS level, ppm 1500PM10, lb/hr 0.015PM10, lb/day 0.18PM10, lb/yr 29.99PM10, tpy 0.015Exhaust ParametersExhaust Temp, deg F 80.0Volumetric flow rate (total), ft3/min590,000.0Fan diameter, ft 9No. of fans 4

Based on 2,000 hrs/yr12 hrs/day

ConstituentEmissions,

lb/hrEmissions,

ton/yrEmissions,

lbs/year

Ammonia 0 ppm 0.0E+00 0.0E+00 0.0Copper 0.01 ppm 1.0E-07 1.0E-07 0.0Silver 0 ppm 0.0E+00 0.0E+00 0.0Zinc 0 ppm 0.0E+00 0.0E+00 0.0

Cadmium 0 ppm 0.0E+00 0.0E+00 0.0Chromium (III) 0 ppm 0.0E+00 0.0E+00 0.0Lead 0 ppm 0.0E+00 0.0E+00 0.0Mercury 0 ppm 0.0E+00 0.0E+00 0.0Nickel 0 ppm 0.0E+00 0.0E+00 0.0Dioxins/furans -- ppm -- -- --PAHs -- -- -- --

2.5E-08 5.0E-05

Notes: 1. Emissions calculated from maximum drift rate of 10.00 lb/hr and

2,000 hrs/yr of operation.2. Based on assumed 20 cycles of concentration

Total HAPs

Emissions (1)

Typical Worst-Case Design Parameters

PM10 Emissions based on TDS Level

Concentration in Cooling Tower Return Water (2)

Hazardous Air Pollutants

8

Rio Mesa SEGF FDOC 9

Table 5.1B-12R2Greenhouse Gas Emissions CalculationsRio Mesa Solar Electric Generating FacilityRevised June 2012

UnitTotal Number of Units (1)

Rated Heat Input, MMBtu/hr

Rated Capacity, MW (Note 1)

Operating Hours per year

Startup Hours per year

Fuel Use, MMBtu/yr (1)

Estimated Gross MWh

Maximum Emissions, metric tonnes/yr

Max. Emissions, tons/yr CO2e

CO2 lb/MWh

CO2 CH4 N2O SF6Auxiliary Boilers 2 249.00444 n/a 1100 865 601656.98 n/a 31899.853 0.601657 0.0601657 --Nighttime Preservation Boilers 2 15.000426 n/a 4780 345 144697.86 n/a 7671.8805 0.1446979 0.0144698 --Power Block Emergency Generators 2 23.8 n/a 200 n/a 9520 n/a 704.0992 0.02856 0.005712 --Common Area Emergency Generator 1 2.72 n/a 200 n/a 544 n/a 40.23424 0.001632 0.0003264 --Power Block Fire Pump Engines 2 1.632 n/a 200 n/a 652.8 n/a 48.281088 0.0019584 0.0003917 --Common Area Fire Pump Engine 1 1.632 n/a 200 n/a 326.4 n/a 24.140544 0.0009792 0.0001958 --WSACs 2 -- n/a 2000 n/a 0 n/a 0 0 0 --Circuit breakers 5 -- n/a 8760 n/a 0 n/a -- -- -- 0.0015282Total -- -- 757398.04 1374000 40388.489 0.7794844 0.0812614 0.0015282CO2-Equivalent 40388.49 16.37 25.19 36.52 44513.23 64.79

Natural Gas GHG Emission Rates (2)

FuelEmission Factors, kg/MMBtu Emission FactorCO2 (3) CH4 (3) N2O (3) SF6 (5)

Natural Gas 53.02 0.001 0.0001 n/aDiesel Fuel 73.96 0.003 0.0006 n/aGlobal Warming Potential (4) 1 21 310 23900

Notes: 1. Rated capacity and heat input from heat balance at annual average conditions, annual fuel use and gross generation based on 100% capacity factor.2. Calculation methods and emission factors from ARB, "Regulation for the Mandatory Reporting of Greenhouse Gas Emissions," December 5, 2007 (Staff's Suggested Modifications to the Originally Proposed Regulation Order Released October 19, 2007). http://www.arb.ca.gov/cc/ccei/reporting/GHGReportRegUpdate12_05_07.pdf3. 40 CFR 98, Table C-14. 40 CFR 98, Table A-1.5. Sulfur hexafluoride (SF6) will be used as an insulating medium in three 230 kV breakers in the common area and in one generator circuit breaker (GCB) at each power block. Estimates of the SF6 contained in a 230 kV breaker range from 161 to 208 lbs, depending on the manufacturer. The GCBs will each contain 24.2 lb of SF6. The IEC standard for SF6 leakage is less than 0.5%; the NEMA leakage standard for new circuit breakers is 0.1%. A maximum leakage rate of 0.5% per year is assumed.

10

Rio Mesa Solar Project NOx CO VOC SOx PM10/2.5Max Annual (tons) 8.3 13.0 3.1 0.8 8.4

Max Daily (pounds) 88.1 111.4 24.1 6.6 17.8

CAS Number Chemical Name HAP lbs/yr75070 Acetaldehyde 0.97

107028 Acrolein 0.8571432 Benzene 1.83

9901 DPM TAC 136.64100414 Ethylbenzene 2.158202

50000 Formaldehyde 3.8677110543 Hexane 1.42

91203 Naphthalene 0.22

1150PAHs (except naphthalene) (4) 0.07speciated PAHsBenzo(a)anthracene 0.01

50328 Benzo(a)pyrene 0.01205992 Benzo(b)fluoranthrene 0.01207089 Benzo(k)fluoranthrene 0.01218019 Chrysene 0.01

53703 Dibenz(a,h)anthracene 0.01193395 Indeno(1,2,3-cd)pyrene 0.01115071 Propylene TAC 84.35108883 Toluene 8.36

1330207 Xylene 6.21E+00

Substance Total

Acetaldehyde 0.970481471

Acrolein 0.854768333Copper 1.0E-07DPM TAC 136.64Ethylbenzene 2.158201863Formaldehyde 3.867738529Hexane 1.419146667Naphthalene 0.219453235PAHs (except naphthalene) (4) 0.073151078speciated PAHsBenzo(a)anthracene 0.006895139Benzo(a)pyrene 0.00459676Benzo(b)fluoranthrene 0.006895139Benzo(k)fluoranthrene 0.006895139Chrysene 0.006895139Dibenz(a,h)anthracene 0.00459676Indeno(1,2,3-cd)pyrene 0.006895139Propylene TAC 84.35003716Toluene 8.358819118Xylene 6.214804608

24.2

Table 1A – Rio Mesa SEGF Maximum Annual HAP (All emissions presented in pounds per year)

Total HAPSNote: Total HAPS do not include Toxic Air

Contaminants (TAC) DPM or Propylene

Rio Mesa SEGF FDOC 11

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1 *indicates change

BEFORE THE ENERGY RESOURCES CONSERVATION AND DEVELOPMENT

COMMISSION OF THE STATE OF CALIFORNIA 1516 NINTH STREET, SACRAMENTO, CA 95814

1-800-822-6228 – WWW.ENERGY.CA.GOV APPLICATION FOR CERTIFICATION FOR THE RIO MESA SOLAR ELECTRIC GENERATING FACILITY

DOCKET NO. 11-AFC-04 PROOF OF SERVICE

(Revised 11/2/12)

APPLICANTS’ AGENTS BrightSource Energy, Inc. Todd Stewart Senior Director, Project Development *Bradley Brownlow Brad DeJean Kwame Thompson 1999 Harrison Street, Suite 2150 Oakland, CA 94612 tstewart@brightsourceenergy.com *bbrownlow@brightsourceenergy.com bdejean@brightsourceenergy.com kthompson@brightsourceenergy.com APPLICANTS’ CONSULTANTS Grenier and Associates, Inc. Andrea Grenier 1420 E. Roseville Parkway Suite 140-377 Roseville, CA 95661 andrea@agrenier.com URS Corporation Angela Leiba 4225 Executive Square, Suite 1600 La Jolla, CA 92037 angela_leiba@urscorp.com APPLICANTS’ COUNSEL Ellison, Schneider & Harris Christopher T. Ellison Brian S. Biering 2600 Capitol Avenue, Suite 400 Sacramento, CA 95816-5905 cte@eslawfirm.com bsb@eslawfirm.com

INTERVENORS Center for Biological Diversity Lisa T. Belenky, Senior Attorney 351 California Street, Suite 600 San Francisco, CA 94104 lbelenky@biologicaldiversity.org Center for Biological Diversity Ileene Anderson Public Lands Desert Director PMB 447, 8033 Sunset Boulevard Los Angeles, CA 90046 ianderson@biologicaldiversity.org INTERESTED AGENCIES Mojave Desert AQMD Chris Anderson, Air Quality Engineer 14306 Park Avenue Victorville, CA 92392-2310 canderson@mdaqmd.ca.gov California ISO e-recipient@caiso.com Bureau of Land Management Cedric Perry Lynnette Elser 22835 Calle San Juan De Los Lagos Moreno Valley, CA 92553 cperry@blm.gov lelser@blm.gov County of Riverside Katherine Lind Tiffany North Office of Riverside County Counsel 3960 Orange Street, Suite 500 Riverside, CA 92501 klind@co.riverside.ca.us tnorth@co.riverside.ca.us

ENERGY COMMISSION – DECISIONMAKERS CARLA PETERMAN Commissioner and Presiding Member carla.peterman@energy.ca.gov KAREN DOUGLAS Commissioner and Associate Member karen.douglas@energy.ca.gov Kenneth Celli Hearing Adviser ken.celli@energy.ca.gov Eileen Allen Commissioners’ Technical Advisor for Facility Siting eileen.allen@energy.ca.gov Jim Bartridge Advisor to Presiding Member jim.bartridge@energy.ca.gov Galen Lemei Advisor to Associate Member galen.lemei@energy.ca.gov Jennifer Nelson Advisor to Associate Member jennifer.nelson@energy.ca.gov ENERGY COMMISSION STAFF Pierre Martinez Project Manager pierre.martinez@energy.ca.gov Lisa DeCarlo Staff Counsel lisa.decarlo@energy.ca.gov ENERGY COMMISSION – PUBLIC ADVISER Jennifer Jennings Public Adviser’s Office publicadviser@energy.ca.gov

2 *indicates change

DECLARATION OF SERVICE

I, Kwame Thompson, declare that on November 5, 2012, I served and filed a copy of the attached document Final Determination of Compliance, dated November 1, 2012. This document is accompanied by the most recent Proof of Service list, located on the web page for this project at: http://www.energy.ca.gov/sitingcases/riomesa/index.html. The document has been sent to the other parties in this proceeding (as shown on the Proof of Service list) and to the Commission’s Docket Unit or Chief Counsel, as appropriate, in the following manner: (Check all that Apply) For service to all other parties: X Served electronically to all e-mail addresses on the Proof of Service list; Served by delivering on this date, either personally, or for mailing with the U.S. Postal Service with first-

class postage thereon fully prepaid, to the name and address of the person served, for mailing that same day in the ordinary course of business; that the envelope was sealed and placed for collection and mailing on that date to those addresses marked *“hard copy required” or where no e-mail address is provided.

AND For filing with the Docket Unit at the Energy Commission: X by sending electronic copies to the e-mail address below (preferred method); OR by depositing an original and 12 paper copies in the mail with the U.S. Postal Service with first class

postage thereon fully prepaid, as follows: CALIFORNIA ENERGY COMMISSION – DOCKET UNIT Attn: Docket No. 11-AFC-04 1516 Ninth Street, MS-4 Sacramento, CA 95814-5512 docket@energy.ca.gov

OR, if filing a Petition for Reconsideration of Decision or Order pursuant to Title 20, § 1720: Served by delivering on this date one electronic copy by e-mail, and an original paper copy to the Chief

Counsel at the following address, either personally, or for mailing with the U.S. Postal Service with first class postage thereon fully prepaid:

California Energy Commission Michael J. Levy, Chief Counsel 1516 Ninth Street MS-14 Sacramento, CA 95814 michael.levy@energy.ca.gov

I declare under penalty of perjury under the laws of the State of California that the foregoing is true and correct, that I am employed in the county where this mailing occurred, and that I am over the age of 18 years and not a party to the proceeding. Original Signed by: Kwame Thompson